Combined dehydration of gas and inhibition of liquid from a well stream

ABSTRACT

A method and system is provided for dehydration of a gas phase and hydrate inhibition of a liquid hydrocarbon phase in a produced multiphase hydrocarbon fluid stream containing water, comprising the steps of:
     i) separating the hydrocarbon fluid stream into a liquid phase and a first gas phase;   ii) adding hydrate inhibitor to the first gas phase; and   iii) separating off condensed liquids and a second gas phase;   wherein the first gas phase has a water dew point which is lower than that of the initial multiphase hydrocarbon fluid stream and the second gas phase has a lower water dew point than the first gas phase;   characterised in that the hydrate inhibitor has a water content that is low enough to enable it to dry the first gas phase, said hydrate inhibitor being separated off with the condensed liquids in step iii) and mixed with a part or all of the liquid phase from the separation in step i) to inhibit said liquid phase.

FIELD OF THE INVENTION

The invention concerns a method and system for the combined dehydrationof gas so that it is able to satisfy subsea transport specifications andinhibition of liquid hydrocarbon phase subsea in a produced multiphasehydrocarbon fluid stream containing water.

BACKGROUND TO THE INVENTION

In the development of remote or marginal offshore oil and gas fields,subsea developments are often selected in order to reduce investments inproduction facilities. Although the hydrocarbons produced on site needprocessing, the number of subsea process units is preferably low and theunits of reduced complexity for minimal maintenance and in order toavoid malfunctions. For further processing it is desirable to utiliseprocess capacity within an hub, infrastructure or on land, which mayrequire transportation over long distances by pipelines.

The hydrocarbon well fluid will often contain both oil and gas which maybe transported to different processing units to utilize capacity ofsurrounding infrastructure. The produced hydrocarbon-containing fluid iswarm when entering the wellhead, generally in the range of 60-130° C.and will in addition to hydrocarbons contain liquid water and water inthe gas phase corresponding to the water vapour pressure at the currenttemperature and pressure. If the gas is transported untreated over longdistances and allowed to cool, the water in gas phase will condense andbelow the hydrate formation temperature, hydrates will form. The hydrateformation temperature is in the range of 20-30° C. between 100-400 bara.

Hydrates are ice-like crystalline solids composed of water and gas, andhydrate depositions at the inside wall of gas and/or oil pipelines is asevere problem in today's oil and gas production infrastructure. Whenwarm hydrocarbon fluid containing water flows through a pipeline withcold walls, hydrates will precipitate and adhere to the inner walls.This in turn will reduce the pipeline cross-sectional area, whichwithout proper counter measures will lead to a loss of pressure andultimately to a complete blockage of the pipeline or other processequipment. Transportation of gas over distance will therefore normallyrequire hydrate control.

Existing technologies that deal with the problem of removing suchdeposits or avoiding them include:

-   -   Mechanical scraping off the deposits from the inner pipe wall at        regular intervals by pigging.    -   Electric heating and insulation keeping the pipeline warm (above        the hydrate appearance temperature).    -   Addition of inhibitors (thermodynamic or kinetic), which prevent        hydrate deposition.

Pigging is a complex and expensive operation. If no loop is available, apig has to be inserted sub-sea using remote-operated vehicles. If morehydrates are deposited than the pig diameter is designed for, the pigmight get stuck in the pipeline, resulting in costly operations and stopin production to remove the pig

Electric heating is not feasible for long-distance transport as bothinstallation and operational costs are too high. Pigging has largeoperational costs.

Another method to reduce or avoid the use of hydrate inhibitor is toinsulate the pipeline and reduce the diameter to increase the flow rateand thereby reduce temperature loss and water accumulation. If thepipeline is not too long, such as in the order of 1-30 km, it will bepossible to keep the temperature above the hydrate formationtemperature, at which hydrates form. However, this reduces theoperational window of the pipeline, and it will not have capacity forfuture higher gas rates and cannot be operated at low gas rates.Boosting might also be required, as the pipeline pressure drop will beimportant due to a small sized pipeline. In addition, hydrate formationwill occur during production stops and shut downs as the hydrocarbonsare cooled below the formation temperature.

To avoid formation of hydrate, a hydrate inhibitor can be added, such asan alcohol (methanol or ethanol) or a glycol such as monoethylene Glycol(MEG or 1,2-ethanediol), which is inexpensive and simple to inject.However, if the water content is high, proportional large amounts ofinhibitor are needed which at the receiving end will require a hydrateinhibitor regeneration process unit with sufficient capacity to recoverand recycle the inhibitor.

Therefore, there is a need for removing both liquid water and water inthe gas phase from a produced hydrocarbon-containing fluid, wherein theratio of liquid and gas phase is dependent on the water vapour pressureat the prevailing temperature and pressure. The water removal in ahydrocarbon-containing gas, or the water dew-point depression, should beperformed before the temperature of the fluid drops below the hydrateformation temperature. In addition, reduced quantities of hydrateinhibitors compared to prior art should be used, i.e. before longtransport by pipeline subsea in cold sea water, such as 5 km or more,for example 10, 20, 30, 50, 75 or 100 km or more.

RU 2199375 concerns a method for absorption drying of hydrocarbon gas byusing a primary separation step and a cooling step where the gastemperature and dew point of gas is controlled by addition of anabsorbent before the cooler, and a second separation step where theabsorbent is regenerated for further transport of the gas. The removalof bulk water in the first separation step reduces the load on theabsorber, but with the use of an absorber at least one regeneration unitis necessary, which is undesirable in subsea installations.

U.S. Pat. No. 5,127,231 concerns the treatment of a gas from aproduction well by contacting the gas with a liquid phase, containingwater and hydrate inhibitor, in a unit separating off a liquid phase andan additive charged gas which is transported over long distances, whichmay be several kilometres. A drying process is described involving acontactor with absorbent (glycol). The gas is cooled during transportbefore entering a heat exchanger where condensate of water solvent andadditive is separated form the gas in a settlement vessel. The liquidphase is recycled to the production site. Hence, hydrate inhibitor isadded during the first separation and is present during the maintransport before cooling, after which the additive is separated at theend reception terminal where the gas is treated.

The methods described above make use of recirculation of anti-hydrateadditive introduced during the first separation step on the well stream.This introduction of additive necessitates an absorber unit forregeneration of the additive.

It was therefore desirable to reduce the number of process units atsubsea and to minimize the amount of hydrate inhibitor used, so that thegas phase from a production well that may be transported over largedistances in cold water without causing hydrate formation, whilerequiring no or little additive regeneration when reaching a processunit.

A suitable process and system is described in prior applicationP61001792N001, which describes a process and system that solves moresatisfactorily the problem of how to bring a subsea well stream to acondition more suited for long distance transport with reducedrequirement for hydrate inhibitor.

The process and system of P61001792N001 can be understood by referenceto FIG. 1. An uninhibited warm well stream 101 enters a first separator110 where the gas phase goes to a gas cooler 120 which cools the wellstream to a temperature above the hydrate temperature (typically 20-25°C.). The purpose of this cooler is to knock out much of the water fromthe gas without the need for the addition of inhibitor.

The gas phase then continues via 108 and hydrate inhibitor 191 may beinjected. A second gas cooler 121 further cools the gas to a temperaturenear the sea temperature (0-10° C.) to further reduce the water contentin the gas.

The majority of the water from 101 and 162 is separated out in 110 andsent via conduit 104 and may be re-injected in the sub-terrainformations by wellhead 140. The remaining liquid continuing in 133consists mainly of oil and condensate, with small amounts of water. Theformation of hydrates in this liquid is inhibited by the liquid stream161, which contains mainly inhibitor (and water and condensate) ifhydrate inhibitor 191 is injected to the gas phase in 108.

The purpose of this invention can thus be seen was to reduce the amountof inhibitor required to inhibit the gas flow 111 and, optionally, theliquid flow 133. This is done by separation of the bulk water in the gasphase by the use of the separators 110, 130, 131.

Although the invention of P61001792N001 addresses the problem ofminimising the amount of hydrate inhibitor used and to some extentreducing the number of process units at subsea, there are a number ofproblems that exist with this. There will always be water in a wellstream, either solved in the gas phase or produced liquid water. Whenthe well stream is cooled, the water in the gaseous phase will condenseinto liquid water. As discussed above, liquid water and hydrocarbonswill form hydrates if the temperature is reduced below approx. 15-25°C., which is the case for the transport from today's subsea satellitefields. As noted above, conventional techniques prior to P61001792N001involved the addition of hydrate inhibitor to the entire well streamwith all the further processing done further downstream. If the amountof water is large, the amount of inhibitor must be correspondinglylarge.

Some recent field developments include a separator at the sea bed totake out bulk water from the liquid phase. The bulk water is re-injectedand thus the need for inhibitor to prevent hydrates in the pipeline isreduced considerably. At the receiving end of the well stream, theinhibitor is recycled and thus it needs regeneration (i.e. removal ofwater). This process is both heat demanding and takes up deck space.Reducing the amount of inhibitor required is therefore beneficial, aproblem that is addressed to a large extent by the process and system ofP61001792N001.

Also, the three phase flow in the pipeline results in a large pressuredrop and it imposes restrictions on the minimum flow velocity due toslugging and riser concerns. At the receiving facility, it also requiresextensive separation and treatment. In particular, the gas treatmenttakes up much space on a platform/FPSO (floating production storage andoffloading facility). The treatment of gas at the receiving facility canalso be a safety concern. For smaller fields remotely located, it mighttherefore be smarter to route the gas from many fields to one commonprocess facility, preferably located on land. It is therefore desirableto achieve the bulk separation of oil and gas and moving the firstprocessing to the seabed, enabling routing the gas to one location andthe liquids to another, both locations being remotely located andpreferably on land. However, in order for this to be achieved it isnecessary for the gas phase to satisfy minimum subsea transportspecifications with respect to water content.

SUMMARY OF THE INVENTION

The present invention provides a method and system for the dehydrationof gas so that it is able to satisfy subsea transport specifications andinhibition of liquid hydrocarbon phase subsea in a produced multiphasehydrocarbon fluid stream containing water.

Thus, in a first aspect of the present invention there is provided Amethod for the dehydration of a gas phase and hydrate inhibition of aliquid hydrocarbon phase subsea in a produced multiphase hydrocarbonfluid stream containing water, the method comprising the steps of:

i) separating the hydrocarbon fluid stream into a liquid phase and afirst gas phase;ii) adding a hydrate inhibitor to the first gas phase; andiii) separating off condensed liquids and a second gas phase;wherein the first gas phase has a water dew point which is lower thanthat of the initial multiphase hydrocarbon fluid stream and the secondgas phase has a lower water dew point than the first gas phase;characterised in that the hydrate inhibitor has a water content that islow enough to enable it to dry the first gas phase so that the secondgas phase is able to satisfy pipeline transport specifications, saidhydrate inhibitor being separated off with the condensed liquids in stepiii) and then mixed with a part or all of the liquid phase from theseparation in step i) to inhibit said liquid phase.

Thus, it can be seen that the method of the present invention is adevelopment of that described in P61001792N001. The key new featuresthat address the problems of the invention (the combined provision of agas stream that is able to satisfy subsea transport specifications and aliquid hydrocarbon phase that is protected from hydrate formation) are:

(a) the addition of hydrate inhibitor having a water content that is lowenough to enable it to dry the gas phase from the first separator sothat the second gas phase is able to satisfy subsea transportspecifications; and(b) the hydrate inhibitor that is separated off with the condensedliquids in step iii) is mixed with the liquid phase from the separationin step i) to provide the required inhibition of hydrate formation inthe liquid phase.

Exactly what level of purity of hydrate inhibitor is required will varydepending upon the water content in the gas and liquid hydrocarbonphase. This can easily be measured at the wellhead and a hydrateinhibitor with the appropriate level of water can be chosen as required.It can thus be seen that in the present invention the same inhibitor isused for multiple purposes, in order to obtain both a gas phase that isdry enough for rich gas transport purposes and a liquid phase which isinhibited against hydrate formation.

In a second aspect of the present invention, there is provided a systemfor the dehydration of a gas phase and hydrate inhibition of a liquidhydrocarbon phase subsea in a produced multiphase stream, wherein thesystem comprises:

ix) a first separator having a multiphase stream inlet, a first gasphase outlet and a liquid phase outlet; andx) a second separator having an inlet, a liquid phase outlet and a gasoutlet; wherein the gas phase outlet of the first separator is in fluidcommunication with the second separator inlet and wherein gas exitingthe first separator gas outlet has a water dew point which is lower thanthat of the multiphase stream entering the first separator;characterised in that the fluid communication means between the firstseparator gas outlet and the second separator inlet comprises anaddition point for hydrate inhibitor, the hydrate inhibitor having awater content that is low enough to enable it to dry the gas so that thesecond gas phase that exits the gas phase outlet of the second separatoris able to satisfy subsea transport specifications, hydrated inhibitorbeing separated off with the condensed liquids via the condensate outletof the second separator and injected into a part or all of the liquidphase from the liquid phase outlet of the first separator to inhibitsaid liquid phase.

DETAILED DESCRIPTION OF THE INVENTION

In the following, it is of importance to specify certain differencesbetween the two terms of “water removal” and gas “drying”.

“Water removal” means removing a bulk amount of water from a stream anddoes not result in a dry gas per se.

“Gas drying” concerns the dehydration of a gas in order to satisfy awater content specification of a pipeline for transport. Suchspecifications vary from pipeline to pipeline. In one typical pipeline,a water dew point of −18° C. at 70 bar is specified. In European salesgas pipelines, a water dew point of −8° C. at 70 bar is specified. Thiscorresponds to a water content from around 80 ppm to 30 ppm, but thespecification can also be outside this range. In general, a water dewpoint below the sea water temperature at 70 bar is typically the minimumrequirement. One preferred embodiment sets a minimum requirement for thewater dew point of 0° C. at 70 bar, which corresponds to a water contentof around 120 ppm. An alternative preferred requirement is a water dewpoint of −8° C. at 70 bar.

In the present invention, the “optional condensate” produced when thefirst gas phase is cooled (see below) comprises C₁ to C₆+ hydrocarbons.Overall, the mixture of liquids that is thus produced after cooling inthe optional second gas cooler and it passes to the second separator isa mixture of water, possibly some C₁ to C₆+ hydrocarbons and hydrateinhibitor. This mixture of liquids exits via the liquid phase outlet ofthe second separator.

The liquid phase mixture that exits via the liquid phase outlet of thefurther separator that can be used between the first and secondseparators (see below) consists of a mixture of water and optionallysome C₁ to C₆ hydrocarbon condensate (the “hydrocarbon condensate”).

The most common prior art method for achieving gas drying is by the aidof absorption wherein water is absorbed by an absorbent. The absorbentmay for example be a glycol (e.g. monoethylene glycol, MEG, ortriethylene glycol, TEG) or an alcohol (e.g. methanol or ethanol). Thementioned need for a low level of water content by use of absorptionalso requires a regeneration plant in order to remove water from theglycol or other absorbent.

Another common prior art method to obtain such low water content in gasdrying is by the aid of expansion and thereby cooling. This method maybe performed by a valve or a (turbo) expander, where the work generatedby the expanding gas may be re-used in a compressor in order to partlyregain the pressure. The temperature of an expander may reach very lowtemperatures, such as below −25° C., and it is therefore necessary toadd a hydrate/ice inhibitor to the gas before it enters the expander.

The present invention concerns combined gas dehydration to give both agas phase that is dry enough to meet the requirements for rich gastransport purposes and a liquid phase which is inhibited against hydrateformation.

By “water knock-out” is understood the removal of water by condensation.

By “gas dehydration” is understood the process of water removal beyondwhat is possible by condensation and phase separation.

By “rich gas” is understood a gas that has a water content low enoughfor transport purposes, a C₃+ content low enough to satisfy cricondenbarspecifications for single phase gas transport but where the content ofC₃+ is too high to satisfy sales gas specifications. A rich gas needsfurther processing to satisfy sales gas specifications.

The present invention enables the production of a rich gas satisfyingtransport properties at the well head as well as inhibiting the liquidphase. The method and system of the present invention produces rich gaswhich can be transported a long distance in single phase pipelinesbefore further treatment. It removes the current need for additionalmeasures for long distance transport of rich gas such as heating, theaddition of further hydrate inhibitor, insulation of the pipeline andpigging. The gas does not need to be brought to the same location as theinhibited liquid phase. For the receiving plant for the liquid stream,as well as savings in process equipment and deck space, the much smallergas treatment facility also reduces operational risk. Gas treatment isoften regarded as a high risk on an FPSO.

Only power and hydrate inhibitor having a water content that issufficiently low to enable it to dry the gas so that the third gas phaseis able to satisfy subsea transport specifications needs to be broughtto the well head. Additionally, a liquid oil/condensate phase with a lowamount of water and also a hydrate inhibitor is produced and can bepumped to one processing plant while the gas phase can be transportedelsewhere, preferably at a location where deck space is less criticalthan offshore.

Until now, one chemical has been used for hydrate inhibition inpipelines and another has been used for dehydration on deck. In thepresent invention, the same chemical is used for both gas dehydrationand hydrate inhibition. This reduces requirements for deck space as aregeneration unit for the chemical used for gas dehydration is notrequired. This simplifies both logistics and storage.

The gas phase from the well stream is now in a single phase that can betransported much further than the multiphase flows in the prior art. Inmost cases, this gas is a rich gas where a further treatment is requiredbefore sales gas specifications can be reached. This treatment can nowbe done at a location further away from the well than in the prior artgas production and transport systems.

However, for some fields, where the gas phase is lean and onlydehydration is required before a sales gas specification is obtained,the gas could be sent directly to a sales gas pipeline if thedehydration is good. Then, only power production and inhibitorregeneration is required at the surface.

At the same time, the liquid (oil, condensate, water) is degassed andsent as a liquid only for further treatment. The liquid phase makes thetransport much simpler than the prior art multi phase pipelines. As thegas volumes reaching the platform/FPSO is dissolved gas in the liquidphase only, the gas treatment facility can be made much smaller.

In a preferred aspect of the present invention, the first gas stream iscooled after mixing with the hydrate inhibitor to condense out water andoptionally a hydrocarbon condensate while keeping the fluid above ahydrate formation temperature thereof.

In one particularly preferred aspect of the present invention, the firstgas phase is separated into an intermediate gas phase and condensedliquids before the addition of the hydrate inhibitor. In this preferredaspect, prior to this further separation the first gas phase may becooled to condense out water and optionally a hydrocarbon condensatewhile keeping the fluid above a hydrate formation temperature thereof.

In another preferred aspect of the present invention, liquid wateradditionally is separated from the produced multiphase hydrocarbon fluidstream in the method of step i) or system of step ix). This separatedliquid water may be re-injected in sub terrain formations.

In a preferred aspect of the first and second embodiments of the presentinvention, the water content of the hydrate inhibitor is such that theresulting dried second gas phase has a water content of no greater than75 ppm or a water dew point of −8° C. at 70 bar.

In one preferred alternative of the first and second embodiments of thepresent invention, the hydrate inhibitor added to the first gas phase orintermediate gas phase has less than 10% water by weight, preferablyless than 5% water by weight, more preferably less than 1% and mostpreferably 0.1% or less water by weight.

In a further preferred aspect of the first and second embodiments of thepresent invention, the hydrate inhibitor added to the first gas phase orintermediate gas phase is selected from the group consisting of glycols,alcohols, thermodynamic ethane and low dosage hydrate inhibitors (LDHI),preferably glycols, more preferably monoethylene glycol (MEG) ortriethylene glycol (TEG) and most preferably monoethylene glycol.

In another preferred alternative of the first and second embodiments ofthe present invention, the separator used to separate off the condensedliquids and the second gas phase comprises a scrubber that is able toremove at least 99% of liquid (water, hydrate inhibitor and hydrocarboncondensate) from the gas phase, preferably at least 99.5% and mostpreferably 99.9%. It is preferable that the scrubber is very efficientto minimise the amount of inhibitor entering the second gas phase thatis then transported. Preferably, this separator that is used to separateoff the condensed liquids and the second gas phase is cooled to atemperature in the range of from −25° C. to +30° C., preferably 0° C. to10° C. Due to the vapour pressure of the inhibitor, traces of inhibitorin vapour form will inevitably follow the second gas phase, but the lowtemperature in the second separator will keep this amount at a minimum.

In a further preferred aspect of the first embodiment of the presentinvention, the condensed liquids from the optional intermediateseparation step are mixed with a part or all of the liquid phase fromthe separation in step i) in the method of the present invention or in afurther preferred embodiment of the second aspect of the invention, thecondensed liquids from the outlet of the further separator are mixedwith a part or all of the liquid phase from the liquid phase outlet ofthe first separator in ix). In this method or system, the liquid phaseis preferably transported to further transporting plants, optionallywith the help of pumping.

In one alternative of the method according to the present invention, thefirst gas phase is cooled down to a temperature in the range of 15-30°C., preferably 20-25° C.

In another preferred aspect of the method according to the presentinvention, the cooled first gas phase is free of hydrate inhibitorand/or absorbent.

Preferably, the optional intermediate gas phase is cooled to atemperature at or below sea temperature, preferably sea temperature,more preferably 0-10° C.

One preferred alternative of the method according to the presentinvention comprises the further following steps:

iv) adding further hydrate inhibitor having a water content as definedabove to the second gas phase while keeping the fluid above a hydrateformation temperature thereof; andv) separating off condensed liquids and a third gas phase;

such that further drying of the second gas phase to give the third phaseis achieved by means of said further hydrate inhibitor, the third gasphase having a lower water dew point than the second gas phase from stepiii).

This is particularly suitable for warm well streams with low watercontent or under conditions where it is difficult to remove water fromthe inhibitor during regeneration. The two drying stages ensure that thegas phase satisfies the subsea transport specifications while alsoensuring that the liquid phase is protected from hydrate formation.

One embodiment of this further preferred alternative comprises thefollowing steps:

vi) adding further hydrate inhibitor having a water content as definedabove to the third gas phase while keeping the fluid above a hydrateformation temperature thereof; andvii) separating off condensed liquids and a fourth gas phase;such that further drying of the third gas phase to give the fourth phaseis achieved by means of the addition of said further hydrate inhibitor,the fourth gas phase having a lower water dew point than the third gasphase.

Another alternative method according to any the present inventioncomprises the further following step:

viii) adding hydrate inhibitor having a water content as defined aboveto the multiphase hydrocarbon fluid stream before the first separationstep (i).

In this case, the same desired effect is achieved by first addinginhibitor at the wellhead (typically several km away) and thenoptionally cooling the well stream before it reaches the dryingfacility. This is particularly suitable for well streams with a loweroil and water content.

In a preferred aspect of the system according to the second embodimentof the present invention, the separator used to separate off thecondensed liquids and the second gas phase is cooled to a temperature inthe range of from −25° C. to +30° C., preferably 0° C. to 10° C.

In one preferred alternative of the system according to the presentinvention, the gas outlet of the second separator is connected to a gastransport conduit for further transport subsea. In this arrangement, thegas transport conduit preferably comprises a compressor or pump.Furthermore, where the gas outlet of the second separator is connectedto a gas transport conduit for further transport subsea, preferably aconduit connects the second gas cooler outlet to the inlet of the secondseparator in which said conduit comprises a regulating choke.

In a further preferred aspect of the system according to the presentinvention, a compact separation technology is used for one or more ofthe separators, preferably an inline separation technology or ascrubber. Preferably, the first separator is a three-phase separatorcomprising a fluid inlet, a gas phase outlet, a liquid condensate outletand a liquid water outlet.

In a further alternative aspect of the system according to the presentinvention, the liquid water outlet of the three-phase separator isconnected to a well head for re-injecting in sub terrain formations.

In a further preferred aspect of the system according to the presentinvention, the second separator used to separate off the condensedliquids and the second gas phase comprises a scrubber that is able toremove at least 99%, preferably at least 99.5% and most preferably 99.9%of liquid from the gas phase.

In a further alternative aspect of the system according to the presentinvention, said system further comprises:

xi) an addition point for adding further hydrate inhibitor having awater content as defined above to the second gas phase outlet whilekeeping the fluid above a hydrate formation temperature thereof; andxii) a third separator having an inlet, a condensate outlet and a gasoutlet;wherein the second separator gas phase outlet is in fluid communicationwith the inlet of the third separator inlet, the third separator liquidphase outlet is in fluid communication with the second separator andwherein gas exiting the third separator gas outlet has a water dew pointwhich is lower than that of the fluid exiting the second separator, suchthat further drying of the second gas phase from the second separator togive a third gas phase is achieved by means of the further hydrateinhibitor.

In a further alternative aspect of the system according to the presentinvention, said system further comprises:

xiii) an addition point for adding further hydrate inhibitor as definedabove to the third gas phase outlet while keeping the fluid above ahydrate formation temperature thereof; andxiv) a fourth separator having an inlet, a liquid phase outlet and a gasoutlet;wherein the third separator gas phase outlet is in fluid communicationwith the inlet of the fourth separator inlet, the fourth separatorliquid phase outlet is in fluid communication with the third separatorand wherein gas exiting the fourth separator gas outlet has a water dewpoint which is lower than that of the fluid exiting the third separator,such that further drying of the third gas phase to give the fourth gasphase is achieved by means of the further hydrate inhibitor. Thesecondensates, including the hydrate inhibitor, can be safely transportedto another destination, e.g. a nearby oil transport hub.

In another preferred aspect, one or both of the condensate outlets ofthe optional further separator and second separator are connected to aconduit for recycling said condensates to the first separator.

By using a subsea cooler, the present invention avoids pressurereduction and is flexible with regards to what cooling temperature isrequired.

In addition the resulting liquid phase remains warm, and it has a muchgreater heat capacity than the gas phase, as a result of which theseparated liquid stream may be transported over long distances before itis cooled to the extent that there is a danger of the formation ofhydrates. However, by suitable choice of the of the hydrate inhibitoradded, it is possible to achieve both the required gas dehydration andinhibition of the liquid phase even where it is being transported overrelatively long distances.

As discussed in the introduction, prior application P61001792N001discloses the use of a separator-cooler-scrubber setup as in the presentinvention in order to remove water and then transfer the gas withminimum injection of hydrate inhibitor. However, neither this priorapplication nor any other document discloses or suggests the combinedprovision of a gas stream that is able to satisfy subsea transportspecifications and a liquid hydrocarbon phase that is protected fromhydrate formation as a result of the addition of a hydrate inhibitorhaving a very low water content to a separated and cooled gas phase inwhich the condensates separated off from the gas phase after addition ofthe inhibitor which contain the added inhibitor are mixed with a part orall of the liquid phase separated off in the separation of the gas fromthe liquid phase. Thus, the same chemical is used for both gasdehydration and the hydrate inhibition. This reduces requirements fordeck space as a hydrate regeneration unit (from the gas) is not requiredand it simplifies both logistics and storage.

High pressure gas can hold less water than low pressure gas. Therefore,the dehydration process preferably occurs at high pressure. Some fieldscould have a very low pressure, such as down to around 10 bar, wheresubsea compression may be required. Then, the dehydration of the presentmay be conducted after first compressing the gas or, alternativelybetween the compression stages. For fields where the pressure ismoderate, say above 50 bar, dehydration can take place at this pressureand compression may optionally be performed on the gas afterwards (aspreviously mentioned).

Alternatively where the gas has a low pressure, the dehydration can takeplace at low pressure if further hydrate inhibitor is injected into thethird gas phase (see further embodiment above), requiring anotherseparator and then a fourth gas phase goes to transport.

DRAWINGS

The present invention will in the following be described in furtherdetail by example embodiments with reference to the appended drawings,none of which should be construed as limiting the scope of theinvention.

FIG. 1 shows a schematic view of a subsea plant for water dew pointdepression and water removal according to the prior applicationP61001792N001.

FIG. 2 shows a schematic view of a subsea plant for gas dehydration,water dew point depression and water removal according to the presentinvention.

FIG. 3 shows a schematic view of an alternative embodiment of a subseaplant for gas dehydration, water dew point depression and water removalaccording to the present invention.

FIG. 4 shows a schematic view of another alternative embodiment of asubsea plant for gas dehydration, water dew point depression and waterremoval according to the present invention.

FIG. 5 shows a schematic view of another alternative embodiment of asubsea plant for gas dehydration, water dew point depression and waterremoval according to the present invention.

FIG. 1 shows an embodiment of a system and method according to priorapplication P61001792N001 wherein an uninhibited warm multiphasehydrocarbon-containing well stream in a pipeline 101 enters a firstseparator 110 where the gas phase goes to a cooler 120 via a conduit 102which cools the well stream to a temperature above the hydratetemperature (20-25° C.). The purpose of this cooler is to knock out muchof the water from the gas without the need for inhibitor. The separatedliquid water phase in conduit 104 separated by the first separator 110may be re-injected in the sub-terrain formations by wellhead 140.

Condensed liquids of water and condensate are passed from the cooler 120by conduit 105 to a second separator 130 such as a condensed waterscrubber, where the phases are separated into a second gas phase exitingat the top by conduit 108 and a liquid phase exiting at the bottom ofthe separator 130 by conduit 106. The second separator 130 may asmentioned earlier be a conventional separator or of more compactseparation technology, e.g. of inline separation technology or ascrubber.

The condensed liquids from the second separator 130 are taken off inconduit 106 and are mixed with the bulk liquid phase in conduit 103,which may be a mainly hydrocarbon containing stream, from the firstseparator to a combined liquid phase in conduit 133.

The water content of the second gas phase in conduit 108 after thesecond separation is reduced, typically the water content is only afraction of the of the original incoming water content of the wellstream in conduit 101.

The second gas phase in conduit 108 is then fed to a second multiphasegas cooler 121. It is suggested in prior application P61001792N001 thata hydrate inhibitor may optionally be added to the gas phase beforeentering the second cooler 121, by an addition/injection conduit 191 inorder to prevent hydrate formation within the cooler. There is, however,no suggestion that hydrate inhibitor having a lower water content thannormal could be used to enable the production of a gas stream that isable to satisfy subsea transport specifications as well as theproduction of a liquid hydrocarbon phase that is protected from hydrateformation.

The cooled second gas phase is separated from any condensates in a thirdseparator 131, such as a condensed water scrubber, where the phases areseparated into a third gas phase exiting at the top by conduit 111 and aliquid phase exiting at the bottom of the separator 131 by conduit 161.This third gas phase may optionally be compressed by a compressor 152before being routed to a gas transport system 112.

The majority of the water from 101 and 162 is separated out in 110 andsent to injection 104. The separated liquid water phase in conduit 104may re-injected in the sub terrain formations by wellhead 140. Theremaining liquid continuing in 133 consists mainly of oil andcondensate, with small amounts of water. It is inhibited by the liquidstream 161, which contains mainly inhibitor, water and condensate. Thecombined liquid phase 103 and small amounts of water together withcondensate and hydrate inhibitor from the outlet 161 of the thirdseparator 131 are combined in the conduit 107. A regulating valve 150 onconduit 103 upstream of the mixing points of conduits 106 and 161 and103 may be present, in order to prevent flashback into the separatorand/or to regulate the mixing rate and composition of said streams. Thiscombined liquid phase is warm and may be transported over long distancesas mentioned above before it cools to a temperature level where hydratesmay form if hydrate inhibitor has not been added.

The purpose of the invention disclosed in P61001792N001 was to reducethe amount of inhibitor required to inhibit the gas flow 111 and liquidflow 133. This was achieved by the separation of the bulk water in thegas phase by the use of the separators 110, 130, 131.

FIG. 2 shows a schematic view of a subsea plant for gas dehydration,water dew point depression and water removal according to the presentinvention. It uses a very similar configuration to the embodiment of theinvention disclosed in P61001792N001.

Specifically a multiphase hydrocarbon-containing well stream in apipeline 201 is first separated into: a first gas phase in a conduit202; a first hydrocarbon liquid phase in a conduit 203; and a liquidwater phase in a conduit 204 by a first three-phase separator 210, whichmay be a conventional separator as described above, wherein theseparated liquid water phase in conduit 204 may re-injected in the subterrain formations by well head 240.

The first gas phase in conduit 202 is cooled in a first multiphase gascooler 220 to knock out water, but above the hydrate formationtemperature. Condensed liquids of water and condensate are passed fromthe cooler 220 by conduit 205 to a second separator 230 where the phasesare separated into a second gas phase exiting at the top by conduit 208and a liquid phase exiting at the bottom of the separator 230. Theliquid phase in conduit 206 may in a first embodiment be connected toconduit 203 containing bulk liquid phase from the first separator 210 asdescribed in prior art embodiment. Alternatively, the liquid phase fromthe first separator may be fed by a conduit 262 back into the firstthree-phase separator 210, for example to reduce the amount of water inthe bulk liquid phase and hence reducing the risk of hydrate formation.

The second gas phase in conduit 208 is then fed to a second multiphasegas cooler 221. Before it reaches the cooler, hydrate inhibitor is addedvia an inlet 291 (e.g. an injection inlet). It is essential that thishydrate inhibitor fed by conduit 291 must have a water content that islow enough to enable it to dry the second gas so that the third gasphase is able to satisfy subsea transport specifications, e.g. MEGcomprising less than 5 wt % water, preferably less than 1 wt % water andmost preferably 0.3 wt % water or less. It is also important that thehydrate inhibitor and gas phase are well mixed, something which mighttake place in a mixing unit (not shown).

It is also as a consequence more important that the scrubber 231 (seebelow) is very efficient, i.e. it can take out as much inhibitor fromthe gas as possible, preferably such that it is able to remove at least99%, preferably at least 99.5% and most preferably 99.9% of the liquidphase entering separator 231. The gas exits the cooler in a conduit 281equipped with a choke valve 251. The choke valve 251 enables regulationof the expansion of the second gas phase and thereby cooling of saidphase down below the sea water temperature due to the Joule Thomson orJoule-Kelvin effect. Possibly, it is also desirable that a pump shouldincrease the pressure in liquid hydrocarbon flow 207.

The cooled second gas phase is separated from any condensates and liquidwater in a third separator 231, and a very dry third gas phase that isable to satisfy subsea transport specifications exits said separator.This third gas phase may optionally be compressed by a compressor 252before being routed to a gas transport system 212.

The condensed liquids from the third separator 231, which include theseparated hydrate inhibitor that was injected into the second gas phase,leave in conduit 261 and are mixed with the bulk liquid phase in conduit203 or 233 from the first separator 210 into a combined liquid phase inconduit 207, which contains very little water when condensates includingwater from the first separator 230 is recycled into the firstthree-phase separator 210. A regulating valve 250 on conduit 203upstream of the mixing points of conduits 261 (and possibly 206) may bepresent, in order to prevent flashback into the first separator and/orto regulate the mixing rate and composition of said streams. As thecombined liquid phase is warm, it contains little water and it containshydrate inhibitor that was originally injected into the second gasphase, this combined liquid phase may as a result be transported overlong distances without hydrate formation occurring.

A compressor or a pump 218 on conduit 207 may be used for boosting orfor ease of transport of the first liquid phase to further processingplants.

Thus, the inhibitor in 261 is used both for dehydration of the gas, andsubsequently, now containing more water, is further used as hydrateinhibitor for the water in the liquid hydrocarbon phase 207. The amountand quality of the inhibitor can be adapted to fit both purposes. Thisenables the production of a very dry gas in conduit 211 which is able tosatisfy subsea transport specifications which can thus be transportedlong distances via a single phase gas pipeline 212 to a gas treatmentplant as well as the production of an inhibited liquid hydrocarbonproduct which contains small amounts of water in a single phase pipeline207. The liquid hydrocarbons, including the inhibitor, can safely betransported to another destination, e.g. to a nearby oil hub. Thehydrated inhibitor is then regenerated. This can be done by means of athermal distillation system. This system typically consists of areclaimer (salt removal) and distillation column. Many such regenerationplants have been built.

FIG. 3 shows a schematic view of an alternative embodiment of a subseaplant for gas dehydration, water dew point depression and water removalaccording to the present invention. Much of the plant is the same asthat described above in relation to FIG. 2. Thus, a multiphasehydrocarbon-containing well stream in a pipeline 301 is first separatedinto: a first gas phase in a conduit 302; a first hydrocarbon liquidphase in a conduit 303; and a liquid water phase in a conduit 304 by afirst three-phase separator 310, which may be a conventional separatoras described above, wherein the separated liquid water phase in conduit304 may re-injected in the sub terrain formations by well head 340.

The first gas phase in conduit 302 is cooled in a first multiphase gascooler 320 to knock out water, but above the hydrate formationtemperature. Condensed liquids of water and condensate are passed fromthe cooler 320 by conduit 305 to a second separator 330 where the phasesare separated into a second gas phase exiting at the top by conduit 308and a liquid phase exiting at the bottom of the separator 330. Theliquid phase in conduit 306 may in a first embodiment be connected toconduit 303 containing bulk liquid phase from the first separator 310 asdescribed in prior art embodiment. Alternatively, the liquid phase fromthe second separator may be fed by a conduit 362 back into the firstthree-phase separator 310, for example to reduce the amount of water inthe bulk liquid phase and hence reducing the risk of hydrate formation.

The second gas phase in conduit 308 is then fed to a second multiphasegas cooler 321. Hydrate inhibitor is injected upstream of the secondcooler 321 via inlet 391. It is essential that this hydrate inhibitorfed by conduit 391 must have a water content that is low enough toenable it to dry the second gas so that the third gas phase is able tosatisfy subsea transport specifications. In order to ensure good mixingof the inhibitor and the gas phase, a mixer might be used where 391enters 308 (not shown). It is also as a consequence more important thatthe scrubber 331 is very efficient, i.e. it can take out as muchinhibitor from the gas as possible, preferably such that it is able toremove at least 99%, preferably at least 99.5% and most preferably 99.9%inhibitor. The cooled second gas phase containing hydrate inhibitorexits the cooler in a conduit 381 equipped with a choke valve 351.

The cooled second gas phase is separated from any hydrocarbon condensateand liquid water in a third separator 331. A third gas phase exits via agas outlet from the third separator 331 to conduit 311. In thisalternative embodiment, conduit 311 is provided with an inlet 392 foradding further hydrate inhibitor to the third gas phase, the inhibitorhaving a water content that is low enough to dry the gas further.Downstream of the point of addition of the further hydrate inhibitor viainlet 392, the third gas phase is fed via the conduit 311 to a fourthseparator 332 having an inlet, a liquid phase outlet and a gas outlet.

Any water and hydrate inhibitor (there will be no hydrocarbon condensatein this further liquid phase) is removed in the fourth separator and avery dry fourth gas phase that is able to satisfy subsea transportspecifications exits via the outlet of said separator and is routed viaa conduit 314. The very dry fourth gas phase may optionally becompressed by a compressor 352 before being routed to a gas transportsystem 312.

The third separator 331 is in gas phase fluid communication with theinlet of the fourth separator. Furthermore, the fourth separator 332condensate outlet is in fluid communication with the third separator 331via conduit 316. The gas exiting the fourth separator gas outlet has awater dew point which is lower than that of the fluid exiting the thirdseparator 331. As a consequence, further drying of the third gas phaseto give the fourth phase is achieved by means of the addition of thefurther hydrate inhibitor via the conduit 392. A draining system, a pumpor other device might be necessary to ensure that the liquid in thebottom of 332 flows into separator 331.

The condensed liquids from the third separator 331 and any liquids fromthe fourth separator 332 which are fed back into the third separator 331via conduit 316, which include the two lots of separated hydrateinhibitor that were injected into the second and third gas phases, leavein conduit 361 and are mixed with the bulk liquid phase in conduit 303or 333 from the first separator 310 into a combined liquid phase inconduit 307, which contains very little water when condensates includingwater from the first separator is recycled into the first three-phaseseparator 310. A regulating valve 350 (not shown) on conduit 303upstream of the mixing points of conduits 361 (and possibly 306) may bepresent, in order to prevent flashback into the first separator and/orto regulate the mixing rate and composition of said streams. As thecombined liquid phase is warm, it contains little water and it containshydrate inhibitor that was originally injected into the second gasphase, this combined liquid phase may as a result be transported overlong distances without hydrate formation occurring.

A compressor or a pump 318 on conduit 307 is used for boosting or forease of transport of the first liquid phase to further processingplants.

Again, the hydrate inhibitor is being used for a dual purpose of dryingthe gas such that it gives a rich gas satisfying transport propertieswhile at the same time inhibiting the liquid stream. This embodiment isparticularly suitable for a warm well stream with low water content.

FIG. 4 shows a schematic view of a further alternative embodiment of asubsea plant for gas dehydration according to the present invention.Much of the plant is the same as that described above in relation toFIG. 2. The embodiment in FIG. 4 is more suited for well streamscontaining less water and oil than the embodiments illustrated in FIGS.1, 2 and 3 and in which the water is solved in the gas phase only. Thus,specifically a multiphase hydrocarbon-containing well stream in apipeline 401 is inhibited several km away from the subsea plant(typically at or near the wellhead) by the addition of hydrate inhibitorvia inlet 490 having a very low water content as previously discussedabove in the relation to the first and second embodiments described forFIGS. 2 and 3.

The cooled, inhibited multiphase stream in the pipeline 401 is thenseparated in a first in-line, compact pre-separator 410 into: a firstgas phase in a conduit 402; and a first liquid hydrocarbon and waterphase in a conduit 403. The liquid phase 403 will contain water, hydrateinhibitor from 490 and possibly also condensed hydrocarbons and otherliquid components from the well stream 401.

The first gas phase in conduit 402 then passes through a short pipelinesegment 402 between the pre-separator 410 and a second separator 430.The second separator separates the first gas phase into a second gasphase which exits via a gas phase conduit and a liquid phase whichmainly comprises water and which exits via conduit 433. The liquid phase403 from the first pre-separator 410 is also fed into this conduit 433,so that the hydrate inhibitor added at the wellhead is added to theliquid hydrocarbons separated in the pre-separator.

A second amount of hydrate inhibitor having a low water content aspreviously discussed above is then added to the second gas phase in theconduit 408 via a conduit 491, optionally with mixing. This second gasphase, having had the second quantity of hydrate inhibitor added to it,then passes via conduit 421 to a third separator 431. In this thirdseparator 431, the second gas phase is separated from any condensates,and a very dry third gas phase that is able to satisfy subsea transportspecifications is produced. This third gas phase exits from the outletof the third separator and passes via conduit 411. It may optionally becompressed by a compressor 452 before being routed via conduit 412 to agas transport system.

The condensed liquids from the third separator 431, which include theseparated hydrate inhibitor that was injected into the first and secondgas phases, leave in conduit 461 and are mixed with the bulk liquidphase in conduit 433 from the second separator 430 into a combinedliquid phase. The combined liquid phase contains water, inhibitor,possibly condensate and dissolved gas. Furthermore, it contains hydrateinhibitor that was originally injected into the multiphase streamupstream of the plant via inlet 490 and that was injected into thesecond gas phase via inlet 491 and which exited via the outlet to thethird separator 431 in conduit 461 to the third separator. This combinedliquid phase in 433 may as a result be transported over long distanceswithout hydrate formation occurring.

A compressor or a pump 418 on conduit 433 may be used for boosting orfor ease of transport of the liquid phase to further processing plantsvia conduit 407.

This alternative embodiment is particularly suitable for well streamswith a lower oil and water content and where the water content in 401 istoo low to justify an oil/water separation as described as separator110, 210 and 310 in FIGS. 1, 2 and 3 respectively.

FIG. 5 shows a schematic view of a further alternative embodiment of asubsea plant for gas dehydration according to the present invention. Asin FIG. 4, this alternative embodiment is particularly suitable for wellstreams with a lower oil and water content and where the water contentin the stream from the wellhead is too low to justify an oil/waterseparation as described as separator 110, 210 and 310 in FIGS. 1, 2 and3 respectively.

Thus, specifically a multiphase hydrocarbon-containing well stream in apipeline 501 is inhibited several km away from the subsea plant(typically at or near the wellhead) by the addition of hydrate inhibitorvia inlet 590 having a very low water content as previously discussedabove in relation to the embodiments described for FIGS. 2, 3 and 4. Ifnot cooled through transport in the pipeline, the inhibited well streamin the pipeline 501 is cooled in a first multiphase gas cooler 510. Thisleads to much of the water in the gas phase to be knocked-out, but isstill above the hydrate formation temperature. It acts both as an inletcooler and as an anti-surge cooler for compressor 552 (see below).

The cooled, inhibited multiphase stream in the pipeline 501 is then fedvia conduit 502 to be separated in a first separator 530 into: a firstgas phase in a conduit 508; and a first liquid hydrocarbon and waterphase in a conduit 533. The liquid phase 533 will contain water, hydrateinhibitor from 590 and possibly also condensed hydrocarbons and otherliquid components from the well stream 501.

The first gas phase in conduit 508 then has a second amount of hydrateinhibitor having a low water content as previously discussed above addedto it via a conduit 591. This cooled first gas phase, having had thesecond amount of hydrate inhibitor added to it, then passes to a secondseparator 531 where it is separated from any condensates, and a very drysecond gas phase that is able to satisfy subsea transport specificationsis produced. This second gas phase exits from the outlet of the secondseparator and passes via conduit 511. It may optionally be compressed bya compressor 552 before being routed to a gas transport system 512.

The condensed liquids from the second separator 531, which include theseparated hydrate inhibitor that was injected into the first gas phase,leave in conduit 561 and are mixed with the bulk liquid phase in conduit533 from the first separator 530 into a combined liquid phase in conduit533. Alternatively, the liquid stream 561 is injected into separator 530to yield an even drier gas leaving 530. The combined liquid phasecontains water, inhibitor, possibly condensate and dissolved gas.Furthermore, it contains hydrate inhibitor that was originally injectedinto the multiphase stream upstream of the plant via inlet 590 and thatwas injected into the first gas phase via inlet 591 and which exited viathe outlet to the second separator 531 in conduit 561 to the secondseparator. This combined liquid phase 533 may as a result be transportedover long distances without hydrate formation occurring.

A compressor or a pump 518 on conduit 533 may be used for boosting orfor ease of transport of the liquid phase to further processing plants.

Thus, it can be seen that these different embodiments are particularlysuitable for different well streams:

-   -   For a well stream with a lot of produced water, FIGS. 2 and 3        are most suited with water reinjection in stream 204/304. Here,        the hydrate inhibitor content can be considerably reduced by        separating out the water before adding hydrate inhibitor. The        additional features in the current application is to provide a        dry gas by also using the inhibitor as drying agent and to use        the liquid mixture comprising inhibitor that is separated off        from the dried gas to inhibit the separated liquid phase.    -   For a well stream with moderate water content (some produced        water), the water injection may not be profitable and the water        goes in line 107/207/307 together with the liquid hydrocarbons.        As no water is removed from the well stream, all the water must        be inhibited. However, the inhibitor provides drying before it        is used as inhibitor. The well stream may or may not be        inhibited at the well head. If it is not inhibited at the well        head, FIG. 2 or FIG. 3 may be employed. If it is inhibited at        the well head, FIG. 4 or 5 are used.    -   For a well stream with water solved in the gas phase only, FIG.        4 or 5 are used with inhibition at the well head.

The present invention may be further understood by reference to thefollowing example.

Example 1

In this example, separation was conducting using a system as shown inFIG. 2. Well stream 201 had a water cut of 10% and a GOR (gas oil ratio)of 1000 at 90 bar and a temperature of 40° C. The flow rate was 250kg/s. This entered a first separator 210. The gas phase and possiblysome liquid (water and possibly some hydrocarbon) exited from the gasphase outlet of the separator 210 in stream 202. Stream 202 entered afirst cooler 220 and was cooled to 25° C. By doing this, the watercontent in the gas phase in stream 205 was reduced by approximately 50%compared to the water content in the gas phase in stream 202 prior toentering the cooler.

The reduced water content stream 202 was fed into a second separator230. A reduced water content gas stream 208 exited the second separator230 and it was then mixed with 11 m³/hour of monoethyleneglycol (MEG)from stream 291. The concentration of MEG in stream 291 was 98% byweight. The mixture of gas and MEG was then cooled in a second cooler221 to a temperature of 8° C. in stream 281. There was in this case nopressure drop or temperature reduction over a valve 251.

The second gas phase and MEG was fed into a third separator 231. Thishad an efficiency of 99.5%, meaning that 99.5% of the liquid phaseentering the separator exited in a liquid stream 261, the remainingliquid exiting with the gas phase in a gas stream 211 via the gas phaseoutlet. The water content in stream 211 was now around 35 ppm which isdry enough to satisfy pipeline transport specifications. This gas mayoptionally be compressed before transport in stream 212.

Most of stream 261 comprised MEG with small amounts of water andpossibly small amounts of hydrocarbon condensate which was mixed withstream 233. The resulting aqueous phase in stream 207 contained above 60wt % MEG which was enough to inhibit stream 207.

Of the 62 tons/hour of water in the well stream 201, more than 56tons/hour was injected into a reservoir in stream 204.

Example 2

At the subsea wellhead, a wellstream 401 at a temperature of around 70°C. contains a rich natural gas which is saturated with water. The wellstream was mixed with inhibitor at a point 490 close to the well head,so that the content of inhibitor was 60% of the total stream ofinhibitor and water, by weight. This well stream was fed into a subseapipeline for transport to a dehydration and compression facility. Due tothe presence of the inhibitor itself and the low temperature that can bekept in the presence of the hydrate inhibitor, the gas phase as a resulthad a water content of around 125 ppm.

The gas phase having a reduced water content produced above wasseparated off in a first in-line, compact separator 410 before passingto a second separator 430 via conduit 402 where it was separated into agas phase and a condensate, which comprised mainly water and hydrateinhibitor. The resulting second gas phase in stream 408 exited the gasoutlet of the second separator and was then passed into a mixer where asecond injection of hydrate inhibitor at 491 took place. This hydrateinhibitor contained around 98% inhibitor by weight. The mixture ofnatural gas in stream 408 and inhibitor in stream 491 then entered athird separation stage 431 where the liquid phase was removed. Theresulting gas phase in stream 411 now contained 30 to 40 ppm water,which corresponds to a dew point of around −18° C. at 70 bar. The waterand hydrate inhibitor separated off in the third separator 431 werepassed via the liquid phase outlet to a conduit 461 which fed thismixture into separator 430. Alternatively, stream 461 was mixed directlywith liquid stream 433. The liquid phase separated off in the firstcomprising condensed hydrocarbons, water and hydrate inhibitor was fedvia the second separator to the liquid phase outlet thereof to theliquid stream 433. The mixture of hydrate inhibitor, water and somecondensed hydrocarbons was transported to a further processing plantusing an optional pump 418.

1. A method for the dehydration of a gas phase and hydrate inhibition ofa liquid hydrocarbon phase subsea in a produced multiphase hydrocarbonfluid stream containing water, the method comprising the steps of: i)separating the hydrocarbon fluid stream into a liquid phase and a firstgas phase; ii) adding a hydrate inhibitor to the first gas phase; andiii) separating off condensed liquids and a second gas phase; whereinthe first gas phase has a water dew point which is lower than that ofthe initial multiphase hydrocarbon fluid stream and the second gas phasehas a lower water dew point than the first gas phase; characterised inthat the hydrate inhibitor has a water content that is low enough toenable it to dry the first gas phase so that the second gas phase isable to satisfy pipeline transport specifications, said hydrateinhibitor being separated off with the condensed liquids in step iii)and then mixed with a part or all of the liquid phase from theseparation in step i) to inhibit said liquid phase.
 2. A methodaccording to claim 1, wherein the first gas phase is cooled after mixingwith the hydrate inhibitor to condense out water and optionally ahydrocarbon condensate while keeping the fluid above a hydrate formationtemperature thereof.
 3. A method according to claim 1 or claim 2,wherein the first gas phase is separated into an intermediate gas phaseand condensed liquids before the addition of the hydrate inhibitor.
 4. Amethod according to claim 3, wherein prior to this further separationthe first gas phase is cooled to condense out water and optionally ahydrocarbon condensate while keeping the fluid above a hydrate formationtemperature thereof.
 5. A method according to any one of claims 1 to 4,wherein the water content of the hydrate inhibitor is such that theresulting dried second gas phase has a water content of no greater than120 ppm.
 6. A method according to any one of claims 1 to 4, wherein thewater dew point of the second gas phase is no greater than 0° C. at 70bar, and preferably no greater than −8° C. at 70 bar.
 7. A methodaccording to any one of claims 1 to 6, wherein the hydrate inhibitoradded to the first or intermediate gas phase has less than 10% water byweight, preferably less than 5% water by weight.
 8. A method accordingto claim 7, wherein the hydrate inhibitor added to the first orintermediate gas phase has less than 1% water by weight, preferably 0.3%water or less by weight.
 9. A method according to any preceding claim,wherein the hydrate inhibitor added to the first or intermediate gasphase is selected from the group consisting of glycols, alcohols and lowdosage hydrate inhibitors (LDHI), preferably glycols.
 10. A methodaccording to claim 9, wherein the hydrate inhibitor added to the secondgas phase is monoethylene glycol, diethylene glycol or triethyleneglycol or a mixture thereof, preferably monoethylene glycol or a mixtureof thereof.
 11. A method according to any preceding claim, wherein theseparator used to separate off the condensed liquids and the second gasphase comprises a scrubber that is able to remove at least 99%,preferably at least 99.5% and most preferably 99.9% of the liquids fromthe gas phase.
 12. A method according to claim 11, wherein the fluidentering the separator used to separate off the condensed liquids andthe second gas phase is cooled to a temperature in the range of −20° C.to +30° C., more preferably 0° C. to 10° C.
 13. A method according toany preceding claim, wherein a conduit is provided to connect the outletof the means for cooling the first phase or intermediate gas phase afteraddition of the hydrate inhibitor to the inlet of the means forseparating off condensed liquids and a second gas phase from said firstgas phase, wherein said conduit comprises a regulating choke.
 14. Amethod according to claim 13, wherein said liquid phase is transportedto further transporting plants, optionally with the help of pumping. 15.A method according to any preceding claim, wherein the first gas phaseis cooled down to a temperature in the range of 15-30° C., preferably20-25° C.
 16. A method according to any preceding claim, wherein thecooled first gas phase is free of hydrate inhibitor and/or absorbent.17. A method according to any preceding claim, wherein the optionalintermediate gas phase is cooled to a temperature at or below seatemperature, preferably sea temperature, more preferably 0-10° C.
 18. Amethod according to any one of claims 1 to 17, comprising the furtherfollowing steps: iv) adding further hydrate inhibitor as defined inclaim 1 to the second gas phase while keeping the fluid above a hydrateformation temperature thereof; and v) separating off condensed liquidsand a third gas phase; such that further drying of the second gas phaseto give the third phase is achieved by means of said further hydrateinhibitor, the third gas phase having a lower water dew point than thesecond gas phase from step iii).
 19. A method according to claim 18,comprising the further following steps: vi) adding further hydrateinhibitor as defined in claim 1 to the third gas phase while keeping thefluid above a hydrate formation temperature thereof; and vii) separatingoff condensed liquids and a fourth gas phase; such that further dryingof the third gas phase to give the fourth phase is achieved by means ofthe addition of said further hydrate inhibitor, the fourth gas phasehaving a lower water dew point than the third gas phase.
 20. A methodaccording to any one of claims 1 to 15 and 17, comprising the furtherfollowing step: viii) adding hydrate inhibitor as defined in claim 1 tothe multiphase hydrocarbon fluid stream before the first separation step(i).
 21. A method according any of the preceding claims, wherein liquidwater additionally is separated from the produced multiphase hydrocarbonfluid stream in step i).
 22. A method according to claim 21, whereinsaid separated liquid water is re-injected in sub terrain formations.23. A method according to any one of claims 1 to 22, wherein the firstgas phase produced from the first separation step is compressed after itexits from the gas outlet of the separator and/or the second gas phaseproduced from the second separation step is compressed after it exitsfrom the gas outlet of the separator.
 24. A system for the dehydrationof a gas phase and hydrate inhibition of a liquid hydrocarbon phasesubsea in a produced multiphase stream, wherein the system comprises:ix) a first separator having a multiphase stream inlet, a first gasphase outlet and a liquid phase outlet; and x) a second separator havingan inlet, a liquid phase outlet and a gas outlet; wherein the gas phaseoutlet of the first separator is in fluid communication with the secondseparator inlet and wherein gas exiting the first separator gas outlethas a water dew point which is lower than that of the multiphase streamentering the first separator; characterised in that the fluidcommunication means between the first separator gas outlet and thesecond separator inlet comprises an addition point for hydrateinhibitor, the hydrate inhibitor having a water content that is lowenough to enable it to dry the gas so that the second gas phase thatexits the gas phase outlet of the second separator is able to satisfysubsea transport specifications, hydrated inhibitor being separated offwith the condensed liquids via the condensate outlet of the secondseparator and injected into a part or all of the liquid phase from theliquid phase outlet of the first separator to inhibit said liquid phase.25. A system according to claim 24, comprising a first gas cooler withtemperature control for water knock out having an inlet and an outlet,said cooler inlet being in fluid communication with the gas phase outletof the first separator.
 26. A system according to claim 24 or claim 25,comprising a further separator having an inlet, a liquid phase outletand a gas outlet between said first and second separators, the inletbeing in fluid communication with the gas phase outlet of the firstseparator and the gas phase outlet of the further separator being influid communication with the second separator.
 27. A system according toany one of claims 24 to 26, comprising a second gas cooler for waterknock out having an inlet and outlet, said cooler inlet being in fluidcommunication with the gas phase outlet of the first separator or thegas phase outlet of the further separator and the outlet being in fluidcommunication with the inlet of the second separator, the cooler beingdownstream from the addition point for hydrate inhibitor.
 28. A systemaccording to any one of claims 24 to 27, wherein the separator used toseparate off the condensed liquids and the second gas phase is cooled toa temperature of from −20° C. to +30° C., more preferably 0° C. to 10°C.
 29. A system according to claim 26, wherein the condensed liquids orknocked out water from the outlet of the further separator are mixedwith a part or all of the liquid phase from liquid phase outlet of thefirst separator in ix).
 30. A system according to any preceding claim,wherein the gas phase outlet of the second separator is connected to agas transport conduit for further transport.
 31. A system according toclaim 30, wherein the gas transport conduit comprises a compressor orpump.
 32. A system according to claim 30 or claim 31, wherein a conduitconnects the outlet of the optional second gas cooler to the inlet ofthe second separator wherein said conduit comprises a regulating choke.33. A system according to any one of claims 24 to 32, wherein a compactseparation technology is used for one or more of the separators,preferably an inline separation technology or a scrubber.
 34. A systemaccording to any one of claims 24 to 33, wherein the first separator isa three-phase separator comprising a fluid inlet, a gas phase outlet, aliquid condensate outlet and a liquid water outlet.
 35. A systemaccording to claim 34, wherein the liquid water outlet of thethree-phase separator is connected to a well head for re-injecting insub terrain formations.
 36. A system according to any one of claims 24to 35, wherein said second separator used to separate off the condensedliquids and the second gas phase comprises a scrubber that is able toremove at least 99%, preferably at least 99.5% and most preferably 99.9%of liquid from the gas phase.
 37. A system according to any one ofclaims 24 to 36, wherein the system further comprises: xi) an additionpoint for adding further hydrate inhibitor as defined in claim 24 to thesecond gas phase outlet while keeping the fluid above a hydrateformation temperature thereof; and xii) a third separator having aninlet, a liquid phase outlet and a gas outlet; wherein the secondseparator gas phase outlet is in fluid communication with the inlet ofthe third separator inlet, the third separator liquid phase outlet is influid communication with the second separator and wherein gas exitingthe third separator gas outlet has a water dew point which is lower thanthat of the fluid exiting the second separator, such that further dryingof the second gas phase from the second separator to give a third gasphase is achieved by means of the further hydrate inhibitor.
 38. Asystem according to claim 37, wherein: xiii) an addition point foradding further hydrate inhibitor as defined in claim 24 to the third gasphase outlet while keeping the fluid above a hydrate formationtemperature thereof; and xiv) a fourth separator having an inlet, aliquid phase outlet and a gas outlet; wherein the third separator gasphase outlet is in fluid communication with the inlet of the fourthseparator inlet, the fourth separator liquid phase outlet is in fluidcommunication with the third separator and wherein gas exiting thefourth separator gas outlet has a water dew point which is lower thanthat of the fluid exiting the third separator, such that further dryingof the third gas phase to give the fourth gas phase is achieved by meansof the further hydrate inhibitor.
 39. A system according to any one ofclaims 24 to 36, wherein the system further comprises: xiv) an additionpoint for adding further hydrate inhibitor as defined in claim 24 to thewell stream upstream of the inlet to the first separator.
 40. A systemaccording to any one of claims 24 to 39, wherein the liquid phaseoutlets of the first and second separators are connected to a conduitfor transport to a further processing plant, optionally connected to apump or compressor for boosting of said transport.
 41. A systemaccording to any one of claims 24 to 39, wherein one or both of theliquid phase outlets of the first and second separators are connected toa conduit for recycling said liquid phases to the first separator.
 42. Asystem according to any one of claims 24 to 41, wherein the first gasphase (or the intermediate gas phase produced using the optional furtherseparator) and the hydrate inhibitor may be mixed by use of a mixingmeans that is situated at or near to where said inhibitor is injectedinto the conduit from the gas outlet of said first or optional furtherseparator.
 43. A system according to any one of claims 24 to 42, whereinthe first gas phase outlet of the first separator is in fluidcommunication with a compressor.